Thermal extenders for well fluid applications

ABSTRACT

The present invention relates to methods and compositions for increasing the effective temperature range for viscosified fluids, including particularly fluids that have been viscosified by the addition of a natural or a natural derivative polymer. In one embodiment, the present invention relates to a method for increasing the effective temperature range for a polymer-viscosified fluid used as a well fluid, which includes adding a miscible tertiary, secondary, and/or primary amine compound into a polymer solution. In another embodiment, the present invention relates to a thermally stable well fluid, which includes a polymer, a solvent, and a tertiary, secondary, and/or primaryamine miscible in the solvent.

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This Application claims the benefit of U.S. Provisional PatentApplication No. 60/295,381, filed on Jun. 1, 2001.

BACKGROUND OF INVENTION

[0002] 1. Field of the Invention

[0003] The invention relates generally to the exploitation ofhydrocarbon-containing formations. More specifically, the inventionrelates to the fields of fluid rheology, thickeners, viscosifiers,viscoelastic fluids, drilling fluids, well fracturing fluids, welltreatment fluids and fluid control pills. The present invention teachescompositions for the creation of and methods of using fluid loss controlpills and similar fluids that can sustain stress conditions for extendedperiods of time without significant fluid loss or loss of desirablerheological properties. The stress conditions may include, for example,exposure to high shear in pumping and placement, exposure to oxidativebreakers, high temperature, high differential pressure, low pH, extendedtime, and a combination of two or more of said stress conditions. Thesepills and fluids are advantageously applied in or in connection withdrilling, drill-in, displacement, completion, hydraulic fracturing,work-over, packer fluid implacement or maintenance, well treating,testing, or abandonment.

[0004] 2. Background Art

[0005] When drilling or completing wells in earth formations, variousfluids typically are used in the well for a variety of reasons. Thefluid often is aqueous. For the purposes herein, such fluid will bereferred to as “well fluid.” Common uses for well fluids include:lubrication and cooling of drill bit cutting surfaces while drillinggenerally or drilling-in (i.e., drilling in a targeted petroliferousformation), transportation of “cuttings” (pieces of formation dislodgedby the cutting action of the teeth on a drill bit) to the surface,controlling formation pressure to prevent blowouts, maintaining wellstability, suspending solids in the well, minimizing fluid loss into andstabilizing the formation through which the well is being drilled,fracturing the formation in the vicinity of the well, displacing thefluid within the well with another fluid, cleaning the well, testing thewell, implacing a packer fluid, abandoning the well or preparing thewell for abandonment, and otherwise treating the well or the formation.Brines (such as CaBr₂) commonly are used as well fluids because of theirwide density range and the fact that brines are typically substantiallyfree of suspended solids. Additionally, brines typically do not damagecertain types of downhole formations.

[0006] A variety of compounds typically are added to the brine-basedwell fluids. For example, a brine-based well fluid also may includecorrosion inhibitors, lubricants, pH control additives, surfactants,solvents, and/or weighting agents, among other additives. Some typicalbrine-based well fluid viscosifying additives include xanthan gum andhydroxyethyl cellulose (HEC).

[0007] The natural and natural derivative polymers and oligomers listedabove have other uses in drilling applications as well. When drillingprogresses to the level of penetrating a hydrocarbon bearing formation,special care may be required to maintain the stability of the wellbore.Examples of formations in which problems often arise are highlypermeable and/or poorly consolidated formations. In these types offormations, a technique known as “under-reaming” may be employed.

[0008] In this process, the wellbore is drilled to penetrate thehydrocarbon bearing zone using conventional techniques. A casinggenerally is set in the wellbore to a point just above the hydrocarbonbearing zone. The hydrocarbon zone then may be re-drilled, for example,using an expandable under-reamer that increases the diameter of thewellbore. Under-reaming usually is performed using special “clean”drilling fluids. Typical drilling fluids used in under-reaming areexpensive, aqueous, dense brines that are viscosified with a gellingand/or cross-linked polymer to aid in the removal of formation cuttings.The high permeability of the target formation, however, may allow largequantities of the drilling fluid to be lost into the formation.

[0009] Once the drilling fluid is lost into the formation, it becomesdifficult to remove. Calcium and zinc-bromide brines can form highlystable, acid insoluble compounds when reacted with the formation orsubstances contained therein. This reaction may reduce the permeabilityof the formation to any subsequent out-flow of the targetedhydrocarbons. The most effective way to prevent such damage to theformation is to limit fluid loss into the formation.

[0010] Thus, providing effective fluid loss control is highly desirableto prevent damaging the formation in, for example, completion, drilling,drill-in, displacement, hydraulic fracturing, work-over, packer fluidimplacement or maintenance, well treating, or testing operations.Techniques that have been developed to control fluid loss include theuse of fluid loss “pills.” Significant research has been directed todetermining suitable materials for the fluid loss pills, as well ascontrolling and improving the properties of the fluid loss pills.Typically, fluid loss pills work by enhancing filter-cake buildup on theface of the formation to inhibit fluid flow into the formation from thewell bore.

[0011] Because of the high temperature, high shear (caused by thepumping and placement), high pressures, and low pH to which well fluidsare exposed (“stress conditions”), the polymeric materials used to formfluid loss pills and to viscosify the well fluids tend to degrade ratherquickly. In particular, for many of the cellulose and cellulosederivatives (such as HEC) used as viscosifiers and fluid control lossagents, significant degradation occurs at temperatures around 200° F.and higher. HEC, for example, is considered sufficiently stable to beused in an environment of no more than about 225° F. Likewise, becauseof the high temperature, high shear, high pressures, and low pH to whichwell fluids are exposed, xanthan gum is considered sufficiently stableto be used in an environment of no more than about 290 to 300° F., orabout 320 to 330° F. in the presence of salts of formate/acetate anions.

[0012] What is needed are natural and natural derivative polymercompositions that can withstand the stress conditions for extendedperiods of time without significant degradation. In particular, what isneeded is a simple, inexpensive way to increase the thermal range forviscosifying agents used in downhole applications. Preferably, thisthermal extender would be applicable to various viscosifying agents(unlike the salts of formate or acetate anions, which only work forxanthan gum).

SUMMARY OF INVENTION

[0013] In one aspect, the present invention relates to a method forincreasing the thermal stability of viscosifying agents, andparticularly polymers, used in a well fluid which comprises mixing amiscible tertiary amine compound into the fluid.

[0014] In another aspect, the present invention relates to a method forincreasing the thermal stability of viscosifying agents, andparticularly polymers, in a well fluid which comprises mixing a misciblesecondary amine compound into the fluid.

[0015] In another aspect, the present invention relates to a thermallystable viscosifying system for well fluids which comprises a polymer, asolvent, and a tertiary amine miscible in the solvent.

[0016] In another aspect, the present invention relates to a thermallystable viscosifying system for well fluids, which comprises a polymer, asolvent, and a secondary amine miscible in the solvent.

[0017] Other aspects and advantages of the invention will be apparentfrom the following description and the appended claims.

DETAILED DESCRIPTION

[0018] The present invention discloses a novel composition forincreasing the thermal durability of natural and natural derivativepolymers used in downhole applications. In general, the invention, inone embodiment, involves the effect of triethanol amine (TEA) on aconventional liquid viscosifier, such as hydroxyethyl cellulose (HEC).HEC is a derivative of cellulose, where the pendant hydroxyl moietieshave been replaced with hydroxyethyl ether groups. The presence of theselong side chains prevent the individual polymer strands from aligningand crystallizing, which allows HEC to be water soluble. The generalstructure of a cellulose polymer is shown below.

[0019] Triethanol amine (TEA) has the following structure:

[0020] In a first embodiment, the effects of high temperatures for longperiods of time were measured on a TEA-containing composition.Specifically, 13.3 milliliters (mL) of TEA was added to a brine/HECmixture. The brine/HEC mixture was formed by the addition of 12.0 mL ofan HEC suspension (41% by weight active component of HEC in dipropyleneglycol methyl ether) to the brine solution. In this embodiment, thebrine solution consisted of 0.965 lab barrels (Lbbl) of a 13.8 poundsper gallon (ppg) CaBr₂ in water. All of the use of the word “barrel” inthis specification relates to “lab barrels” —a lab barrel is equivalentto about 350 milliliters. (A lab barrel of water weighs about 350 grams,just as a regular barrel of water weighs the same number of pounds,about 350. This is the formal origin of the term “lab barrel.”Fortunately, a lab barrel of any fluid—regardless of density—happens tohave the same volume as that of a lab barrel of water). Additionally,while the particular embodiments describe a particular order of additionfor the chemical components, such a description is not intended to limitthe scope of the invention in any fashion.

[0021] After mixing the components, initial Theological parameters weremeasured. The rheological measurements were made using a Fann model 35rotational viscometer (manufactured by Fann Instrument Co., of Houston,Tex.), using a B 1 bob on a “2 times” spring. Specifically, the apparentviscosity was measured. Viscosity is the ratio of the shear stress tothe shear rate and is an indication of flow resistance. For many fluids,apparent viscosity changes for different values of shear rate, and ismeasured in centiPoise (cP). Shear rate is measured in RPM or sec⁻¹.

[0022] In this embodiment, the initial apparent viscosity of thebrine/TEA/HEC mixture was measured at six different shear rates: 600rpm, 300 rpm, 200 rpm, 100 rpm, 6 rpm, and 3 rpm. Additionally, theinitial pH of the brine/TEA/HEC mixture was measured. The brine/TEA/HECmixture was then placed in an oven at 245° F. After 20 hours, thebrine/TEA/HEC mixture was removed from oven and allowed to cool to roomtemperature. After reaching room temperature, the apparent viscosity andpH of the mixture was again measured. After taking the measurement, themixture was returned to the oven and left in the oven for 24 hours at245° F. Measurements of the pH and apparent viscosity were again takenafter the mixture was allowed to cool to room temperature. The mixturewas then returned to the oven for an additional 25 hours at 245° F.,after which the sample was allowed to cool and final measurements weretaken.

[0023] The results are summarized below: TABLE 1 13.3 ML TEA PRESENT(APPARENT VISCOSITY) Shear Rate (RPM) Initial 20 Hrs 44 Hrs 75 Hrs 600631 647 648 645 (estimated) (estimated) (estimated) (estimated) 300 530542 526 508 200 502 490 488 470 100 436 422 422 400  6 236 214 202 174 3 196 172 160 134 pH 7.57 7.3 7.44 7.33

[0024] Table 1 shows that the apparent viscosity of the brine/TEA/HECmixture remained roughly constant during the entire 75 hour heattreatment. Further, the pH of the mixture also remained roughlyconstant. Based on these results, it is evident that the HEC polymersuffered no significant degradation during the entire 75 hour experimentwhen treated with TEA.

[0025] For comparison, an experiment was run under conditions similar tothose described above without the addition of TEA. In this experiment,12.0 mL of an suspension (41% by weight active component of HEC indipropylene glycol methyl ether) was poured slowly into an agitatedbrine solution. As in the previous experiment, the brine solutionconsisted of 0.965 Lbbl of a 13.7 ppg CaBr₂ in water.

[0026] Again, the initial apparent viscosity of the brine/HEC mixturewas measured at six different shear rates: 600 rpm, 300 rpm, 200 rpm,100 rpm, 6 rpm, and 3 rpm. In addition, the initial pH was measured. Asabove, the brine/HEC mixture was placed in an oven at 245° F. andmeasurements were taken after 20, 44, and 75 hours.

[0027] The results are summarized below: TABLE 2 COMPARATIVE RUN, TEAABSENT (APPARENT VISCOSITY) Shear Rate (RPM) Initial 20 Hrs 44 Hrs 75Hrs 600 596 662 420 166 (estimated) 300 504 506 294 93 200 460 452 23865 100 396 372 154 35  6 204 142 16 4  3 164 102 10 3 pH 5.9 6 4.68 5.43

[0028] As shown in Table 2, absent the TEA, viscosity reduction becomessignificant at the times/temperatures associated with this experiment.For example, a dramatic loss in viscosity occurred within 44 hours intothe experiment. Also noticeable is the fact that the pH of the systemwas significantly lower than that of the TEA-containing system describedabove. Thus, experimental evidence has determined that the TEA mayprovide a buffering effect to maintain the pH of the system at a pH ofapproximately 7. A discussion of why the buffering effect is believed tobe significant is provided below.

[0029] In a second embodiment, 49.4 mL of an HEC/TEA slurry was added to0.859 Lbbl of a 14.18 ppg gallon CaBr₂ in water. The HEC/TEA slurry wasformed by the addition of 91 pounds of TEA to 9 pounds of HEC powder.The resulting slurry, therefore, comprises 9% by weight HEC.

[0030] As in the embodiment described with respect to Table 1, theinitial apparent viscosity of the HEC slurry was measured at sixdifferent shear rates: 600 rpm, 300 rpm, 200 rpm, 100 rpm, 6 rpm, and 3rpm. In addition, the pH was measured.

[0031] As above, the brine/HEC/TEA mixture was placed in an oven at 245°F. and measurements were taken after 20, 47.5, and 73.5 hours, havingallowed the solution to cool to room temperature before measuring.

[0032] The results are summarized below. TABLE 3 RESULTS FROM HEC/TEASLURRY (APPARENT VISCOSITY) Shear Rate (RPM) Initial 20 Hrs 47.5 Hrs73.5 Hrs 600 644 604 682 659 (estimated) (estimated) (estimated)(estimated) 300 560 512 578 520 200 520 464 522 464 100 464 404 440 384 6 270 210 228 160  3 232 174 186 120 pH 7.44 7.35 7 7.2

[0033] As in the first embodiment, it is apparent from examining theresults in Table 3 that no significant viscosity degradation occurred.Polymer degradation causes a loss in viscosity because, as the polymerdecomposes (a mechanism for this decomposition is proposed below), thehigh molecular weight chains become substantially lower molecular weightchains. As more low-molecular-weight chains are formed from thedecomposition of the high molecular weight chains, the entanglementsamong the polymer chains decreases, which allows the polymer chains toflow more freely past one another and thereby decreases fluid viscosity.It is clear from Table 3 that even if the TEA is added as part of apolymer slurry, there is no reduction in the ability of TEA to increasethe temperature stability of a polymer solution.

[0034] In a third embodiment, the effects of TEA in the presence ofother common additives was measured. Also, a suspension of HEC insynthetic oil rather than an organic solution was used to determinewhether TEA would have a similar effect as in the other embodiments.Specifically, 12.5 mL of a suspension of HEC (41% active component HECby weight in a synthetic oil solvent) was mixed into 0.916 Lbbl of a13.9 ppg brine solution. In addition, a trace amount of an oxygenscavenger (sodium thiosulfate pentahydrate in this embodiment) was mixedas a dry reagent into the system. 13.3 mL of TEA was then added to theHEC/brine system. In this embodiment, CaBr₂ was used to create the brinesolution.

[0035] As in the above embodiment, the initial apparent viscosity of thebrine/HEC mixture was measured at six different shear rates: 600 rpm,300 rpm, 200 rpm, 100 rpm, 6 rpm, and 3 rpm. In addition, the pH wasmeasured. The brine/HEC/TEA mixture was placed in an oven at 245° F. andmeasurements were taken after 21.5, 47, and 87 hours, allowing themixture to cool to room temperature prior to measuring pH and viscosity.

[0036] The results are tabulated below. TABLE 4 HEC IN SYNTHETIC OILSUSPENSION/OXYGEN SCAVENGER PRESENT (APPARENT VISCOSITY) Shear Rate(RPM) Initial 21.5 Hrs 47 Hrs 87 Hrs 600 510 731 623 670 (estimated)(estimated) (estimated) 300 410 625 510 520 (estimated) 200 366 570 468468 100 306 490 400 396  6 154 264 192 160  3 130 220 152 118 pH 6.996.87 6.5 6.5

[0037] It is apparent from Table 4 that changing the composition of theHEC suspension in the manner described above has no apparent effect onthe ability of TEA to provide thermal stability to HEC polymers. Inaddition, it may be noted that, in this embodiment, the mixture wassubjected to heat treatment for 87 hours. Even at this prolongedexposure, no major decomposition was noted. It may be noted that thepresence of the oxygen scavenger appeared to have no effect on themixture. Further, the pH of the system remained substantially constant,which is an indication that the TEA provides the same buffering effectas with higher HEC concentrations.

[0038] As a comparison, 12.5 mL of a suspension of HEC (41% activecomponent in a synthetic oil solution) was added to 0.916 Lbbl of a 13.9ppg brine solution. To the HEC/brine mixture, 13.3 mL of TEA was added.As in the above embodiment, the brine solution comprised CaBr₂ in water.

[0039] As in the above embodiment, the initial apparent viscosity of themixture was measured at six different shear rates: 600 rpm, 300 rpm, 200rpm, 100 rpm, 6 rpm, and 3 rpm. In addition, the initial pH wasmeasured. As above, the brine/HEC/TEA mixture was placed in an oven at245° F. and measurements were taken after 21, 45, and 70 hours, allowingthe mixture to cool prior to measuring.

[0040] The results are tabulated below. TABLE 5 HEC IN SYNTHETICSUSPENSION/NO OXYGEN SCAVENGER PRESENT (APPARENT VISCOSITY) Shear Rate(RPM) Initial 21 Hrs 45 Hrs 70 Hrs 600 280 633 624 578 (estimated)(estimated) 300 214 526 494 510 200 186 496 444 420 100 146 426 368 344 6 56 224 156 132  3 44 182 118 96 pH 7.4 7.3 7 7

[0041] The above results confirm that the addition of an oxygenscavenger to the TEA/HEC/brine mixture has no significant effect on theability of TEA to provide thermal stability to the polymer system.

[0042] In a fourth embodiment, the effect of TEA on polymer stability inmixed brine systems was measured. In addition, the effect of TEA in thepresence of lower concentrations of HEC suspensions was measured.Specifically, 43.8 pounds of a suspension of HEC (9% by weight of HECsuspended in ethylene glycol) was added to 0.796 Lbbl of 16.2 pounds pergallon ZnBr₂ /CaBr₂ in water. The 16.2 pounds per gallon brine solutionwas formed by the dilution of a 19.2 pounds per gallon ZnBr₂ /CaBr₂mixture with water. In this embodiment, the initial 19.2 pounds pergallon ZnBr₂/CaBr₂ water mixture is 52.8% by weight ZnBr₂, 22.8% CaBr₂,with the balance water. To this, 19.9 pounds of TEA was added.

[0043] As in the above embodiments, the initial apparent viscosity ofthe mixture was measured at six different shear rates: 600 rpm, 300 rpm,200 rpm, 100 rpm, 6 rpm, and 3 rpm. In addition, the pH was measured.The brine/HEC/TEA mixture was placed in an oven at 235° F. andmeasurements were taken after 14, 35, and 52 hours, allowing the mixtureto cool prior to measuring.

[0044] The results are tabulated below. TABLE 6 MIXED BRINE SOLUTION(APPARENT VISCOSITY) Shear Rate (RPM) Initial 14 Hrs 35 Hrs 52 Hrs 600660 354 124 72 (estimated) 300 582 226 64 37 200 526 168 44 25 100 45696 22 12  6 266 6 2 1  3 226 4 1 0 pH 3.8 4 4.1 4.3

[0045] As shown in Table 6, viscosity reduction becomes significant atthe times/temperatures associated with this experiment, despite thepresence of TEA. For example, a dramatic loss in viscosity has occurred14 hours into the experiment. Also noticeable is that the pH of thesystem was significantly lower than that of the TEA containing systemsdescribed above. The loss of viscosity even in the presence of TEA wasattributed to the low pH of this system. The propensity of zinc bromidebrines to cause low pH has previously been noted, for example, in U.S.Pat. No. 6,100,222, issued to Vollmer, et al. Basically, the inherentacidity of zinc bromide brines leads to the relatively low pH's measuredin Table 6.

[0046] For comparison, an experiment was run under similar conditions asabove, but the relative concentration of ZnBr₂ was decreased.Specifically, 36.2 pounds of a suspension of HEC (9% by weight of HECsuspended in ethylene glycol) was added to 0.855 Lbbl of 16.2 pounds pergallon ZnBr₂ /CaBr₂ in water. The 16.2 pounds per gallon brine solutionwas formed by the dilution of a 19.2 pounds per gallon ZnBr₂ /CaBr₂mixture (having the same composition as in the above embodiment) with14.2 pounds per gallon CaBr₂ in water. To this, 12.8 pounds of TEA wasadded.

[0047] As in the above embodiments, the initial apparent viscosity ofthe mixture was measured at six different shear rates: 600 rpm, 300 rpm,200 rpm, 100 rpm, 6 rpm, and 3 rpm. In addition, the pH was measured.The brine/HEC/TEA mixture was placed in an oven at 250° F. andmeasurements were taken after 22.5, 39, 61, 78.5, and 93.5 hours,allowing the mixture to cool prior to measuring.

[0048] The results are tabulated below. TABLE 7 LOWER RELATIVE ZINC(APPARENT VISCOSITY) Shear Rate 22.5 39 61 78 93.5 (RPM) Initial Hrs HrsHrs Hrs Hrs 600 568 606 576 588 574 534 (estimated) (estimated) 300 502494 450 460 432 400 200 444 436 394 398 370 338 100 372 358 314 308 280248  6 208 160 108 98 66 50  3 178 124 76 58 40 28 pH 5.2 5.3 5.9 5.85.9 5.8

[0049] As shown in Table 7, viscosity reduction becomes significant atthe times/temperatures associated with this experiment, despite thepresence of TEA. However, the viscosity reduction is not as great as thereduction seen in Table 6. It also may be noted that the pH's in Table 7are higher (less acidic) than those seen in Table 6. This experimentalevidence further supports the mechanism described below.

[0050] Like HEC, TEA is miscible in water, which prevents anyundesirable phase separation. While the foregoing embodiments referencea limited number of compounds, it should be recognized that chemicalcompounds having the same general characteristics also will function inan analogous fashion. For example, it is expressly within the scope ofthe present invention that methyldiethanol amine (MDEA), dimethylethanolamine (DMEA), diethanol amine (DEA), monoethanol amine (MEA), or othersuitable tertiary, secondary, and primary amines and ammonia could besubstituted, in whole or in part, for the triethanol amine describedherein. In addition, it also is expressly within the scope of theinvention that other mixed TEA systems may be used as additives, such asa TEA/glycol system or a TEA/alcohol system. Suitable alcohols wouldinclude methanol, ethanol, n-propanol and its isomers, n-butanol and itsisomers, n-pentanol and its isomers, n-hexanol and its isomers, etc.

[0051] Similarly, other natural and natural derivative polymers may besubstituted for HEC, such as, for example, starch, derivatized starch,or xanthan gum. Furthermore, it should be noted that while the aboveexamples discuss the utility of amines in CaCl₂ containing brinesolutions, it will be clear to one of ordinary skill in the art thatother brine solutions, such as ZnCl₂, CaBr₂, and ZnBr₂, NaCl, KCl,NH₄Cl, MgCl₂, seawater, NaBr, Na₂S₂O₃, and combinations thereof, may beused.

[0052] In addition, while specific amounts of the chemicals used aredescribed in the above embodiments, it is specifically within thecontemplation of the invention that amounts different than thosedescribed above may be used to provide the desired thermal stability,depending on the particular application. For example, in one embodiment,a suitable system for increasing polymer stability may comprise 0.1% byweight to 50% by weight HEC and 0.1% by weight to 50% by weight TEA.More preferably, in one embodiment the system may comprise 0.1% byweight to 5% by weight HEC and 0.2% by weight to 20% TEA. Still morepreferably, in one embodiment the system may comprise 0.3% by weight to1.5% by weight HEC and 0.5% by weight to 10% by weight TEA.

[0053] Therefore, in some embodiments, it is expressly within the scopeof the invention that no water or brine will be present. In addition, nolimitation should be placed on the use of other systems such as aTEA/glycol/HEC system or a TEA/glycol/HEC/brine system. Other systemsexpressly within the scope of the present invention include TEA/alcoholadditives.

[0054] One proposed mechanism for how the addition of TEA providesadditional thermal stability is based on the belief that TEA may act asa pH buffer. Because HEC is derived from cellulose, many of thereactions that are associated with cellulose are relevant to thechemistry of HEC and other related biopolymers (such as starch).Specifically, acid catalyzed hydrolysis can cause degradation ofcellulose. Acids (which are present in downhole formations because ofthe release of acid gases such as H₂S) attack the acetal linkages,cleaving the 1-2 glycosidic bond, as labeled in Equation 1. The carbonatom labeled 2 in Equation 1 may be considered an acetal. Generallyspeaking, an acetal is simply a diether in which both ether oxygens arebound to the same carbon. Acetals typically are much more stable towardalkali and, base-catalyzed hydrolysis is much less likely to occur.Thus, by keeping the pH above the base brine pH, or as near to 7 aspossible, TEA may serve to prevent an acid-catalyzed degradation of HEC.

[0055] In the above discussion involving an acid-catalyzed mechanismsfor polymer degradation, it should be noted explicitly that bothBronsted-Lowry and Lewis definitions of acids are equally applicable.Thus in aqueous systems where acids may be present and acting as suchthrough the Bronsted-Lowry definition of an acid, the role of the acidwould be that of a “proton-donor” while the complementary role of theTEA would be that of a “proton-acceptor”. Furthermore, in systems suchas, for example, those containing the Lewis acid zinc bromide, where theacid may be acting as such through the Lewis definition of an acid, therole of the acid would be that of an “electron-acceptor” while thecomplementary role of the TEA would be that of a “electron-donor.”

[0056] Another embodiment of this invention is the ability of the TEA toimprove the hydration time of HEC and the transition temperature atwhich solutions of HEC in monovalent brines (such as KCl and NaCl) ‘saltout,’ or separate into distinct phases (i.e., syneresis). Typically thisphase separation manifests by the appearance of a phase of higher thanoriginal HEC concentration, usually floating on top of a lower viscositylayer. In many cases, the HEC will actually precipitate completely outof solution.

[0057] Two 10.0 lbm/gal NaCl brines, one treated with 0.043 vol % TEAand the other untreated, were used to measure the effect of TEA onhydration time and transition temperature. Both brines were viscosifiedwith Union Carbide HEC 10 at 4 lbm/bbl concentration. Both samplesviscosified, however, the TEA treated brine developed full viscosity inseveral minutes whereas the untreated brine required over 1 hour ofmixing to fully viscosify. Thus, the addition of TEA significantlyimproved the hydration time.

[0058] Initial rheology measurements of the two fully viscosified brineswere taken using a Fann 35 rheometer at room temperature. The solutionswere then heat-aged in an oven at 180° F. for 22 hours, and then removedand allowed to cool to room temperature. Rheological measurements onboth brines were then taken on the Fann 35. As can be seen in Table 8below, the TEA-treated solution was homogeneous in appearance andTheological properties, whereas the untreated solution formed separatephases in which HEC was concentrating and salting out of solution, withthe top phase considerably more viscous than the lower phase, butneither phase quite so viscous as the homogeneous TEA-treated solution.Clearly, some of the HEC salted-out and no longer contributed fully tothe viscosity of the un-TEA-treated fluid.

[0059] The results are tabulated below. TABLE 8 EFFECT OF TEA ONHYDRATION TIME AND TRANSITION TEMPERATURE After Heat Aging TEA- TEA-Dial Initial Untreated Untreated Treated Treated Reading TEA- Bottom TopBottom Top (rpm) Untreated Treated Layer Layer Portion Portion 600 321285 100 230 258 255 (est.) 300 260 235 77 190 215 210 200 236 213 65 168192 187 100 200 179 49 137 157 152  6 90 77 12 51 52  50  3 73 59 8 3735 33

[0060] Table 8 shows that, after heat aging, there is substantially nodifference in viscosity between the top and bottom portion of theHEC/brine/TEA solution. However, after heat aging, Table 8 shows thatdistinct phases exist in the HEC/brine solution. Specifically, thebottom layer in the non-TEA containing solution, has a substantiallyloss in viscosity, which may be attributed to the aforementioned ‘saltout’ effect.

[0061] The present invention advantageously increases the effectivetemperature range for natural polymer systems in an inexpensive,easy-to-implement method. The addition of miscible amines into thepolymer system dramatically increases the temperature resistivity of thesolution. Further, the present invention advantageously improves thehydration time and the transition temperature of natural polymer systemsin monovalent brines.

[0062] While the invention has been described with respect to a limitednumber of embodiments, those skilled in the art, having benefit of thisdisclosure, will appreciate that other embodiments can be devised whichdo not depart from the scope of the invention as disclosed herein.Accordingly, the scope of the invention should be limited only by theattached claims.

What is claimed is:
 1. A method for increasing the thermal stability ofa well fluid comprising: mixing an effective amount of a miscible aminein the well fluid, wherein the well fluid comprises a natural polymer.2. The method of claim 1, wherein the miscible amine comprises an amineselected from the group consisting of primary, secondary and tertiaryamines, and mixtures thereof.
 3. The method of claim 1, wherein theamine comprises about 0.2% to about 20% by weight of the well fluid. 4.The method of claim 3, wherein the amine comprises about 0.5% to about10% by weight of the well fluid.
 5. The method of claim 3, wherein thenatural polymer comprises about 0.1% to about 5% by weight of the wellfluid.
 6. The method of claim 4, wherein the natural polymer comprisesabout 0.3% to about 1.5% by weight of the well fluid.
 7. The method ofclaim 1, wherein the natural polymer comprises hydroxyethylcellulose. 8.The method of claim 1, wherein the miscible amine comprises triethanolamine.
 9. A method for increasing the thermal stability of a well fluidcomprising: mixing about 0.1% to about 50% by weight of a miscible amineinto the well fluid, wherein the well fluid comprises a natural polymer.10. The method of claim 9, wherein the miscible amine comprises an amineselected from the group consisting of primary, secondary and tertiaryamines, and mixtures thereof.
 11. The method of claim 10, wherein theamine comprises about 0.2% to about 20% by weight of the well fluid. 12.The method of claim 11, wherein the amine comprises about 0.5% to about10% by weight of the well fluid.
 13. The method of claim 11, wherein thenatural polymer comprises about 0.1% to about 5% by weight of the wellfluid.
 14. The method of claim 12, wherein the natural polymer comprisesabout 0.3% to about 1.5% by weight of the well fluid.
 15. The method ofclaim 9, wherein the natural polymer comprises hydroxyethylcellulose.16. The method of claim 9, wherein the miscible amine comprisestriethanol amine.
 17. A thermally stable well fluid comprising: anatural polymer; and an effective amount of miscible amine.
 18. The wellfluid of claim 17, wherein the miscible amine comprises an amineselected from the group consisting of primary, secondary and tertiaryamines, and mixtures thereof.
 19. The well fluid of claim 18, whereinthe amine comprises about 0.2% to about 20% by weight of the well fluid.20. The well fluid of claim 19, wherein the amine comprises about 0.5%to about 10% by weight of the well fluid.
 21. The well fluid of claim19, wherein the natural polymer comprises about 0.1% to about 5% byweight of the well fluid.
 22. The well fluid of claim 20, wherein thenatural polymer comprises about 0.3% to about 1.5% by weight of the wellfluid.
 23. The well fluid of claim 17, wherein the natural polymercomprises hydroxyethylcellulose.
 24. The well fluid of claim 17, whereinthe miscible amine comprises triethanol amine.
 25. A method of treatinga well comprising: injecting a well treating fluid into the well,wherein the well treating fluid comprises a natural polymer and amiscible amine.
 26. The method of claim 25, wherein the miscible aminecomprises an amine selected from the group consisting of primary,secondary and tertiary amines and mixtures thereof.
 27. The method ofclaim 25, wherein the natural polymer comprises hydroxyethylcellulose.28. The method of claim 25, wherein the miscible amine comprisestriethanol amine.
 29. The method of claim 25, wherein the miscible aminecomprises about 0.1% to about 50% by weight of the well treating fluid.30. The method of claim 29, wherein the miscible amine comprises about0.2% to about 20% by weight of the well treating fluid.
 31. The methodof claim 29, wherein the natural polymer comprises about 0.1% to about5% by weight of the well fluid.
 32. The method of claim 30, wherein thenatural polymer comprises about 0.3% to about 1.5% by weight of the wellfluid.
 33. A method for increasing hydration time and transitiontemperature in a well fluid comprising: mixing an effective amount of amiscible amine with a natural polymer.
 34. The method of claim 33,wherein the miscible amine comprises an amine selected from the groupconsisting of primary, secondary and tertiary amines and mixturesthereof.
 35. The method of claim 33, wherein the natural polymercomprises hydroxyethylcellulose.
 36. The method of claim 33, wherein themiscible amine comprises triethanol amine.
 37. The method of claim 33,wherein the miscible amine comprises about 0.1% to about 50% by weightof the well fluid.
 38. The method of claim 37, wherein the miscibleamine comprises about 0.2% to about 20% by weight of the well fluid.